With energy usage directly related to economic growth, there has been a steady increase in the need for increased energy supplies. In the U.S., coal is abundant and comparatively low in cost. Unfortunately, conventional coal-fired steam power plants, which are a major source of electrical power, are inefficient and pollute the air. Thus, there is a pressing need for cleaner, more efficient coal-fired power plants. Accordingly, Integrated Gasification Combined Cycle (“IGCC”) coal technology systems have been developed which can achieve significantly improved efficiencies in comparison to conventional steam plants. In such a system, syngas (a mixture of hydrogen and carbon monoxide) is produced by partial oxidation of coal or other carbonaceous fuel. This allows cleanup of sulfur and other impurities, including mercury, before combustion.
Concern over global warming resulting from carbon dioxide emissions from human activity, primarily the combustion of fossil fuels, has led to the need to sequester carbon. If carbon dioxide sequestration is desired, the carbon monoxide can be reacted with steam using the water gas shift reaction to form carbon dioxide and hydrogen. Carbon dioxide may then be recovered using conventional technologies known in the art. This allows pre-combustion recovery of carbon dioxide for sequestration. Removal of the carbon dioxide leaves a fuel gas much richer in hydrogen. Unfortunately, there is an issue for low NOx combustion for these high hydrogen fuels.
As a result of the high flame speed of hydrogen, flashback is likely with premixed dry low NOx combustion systems. Flashback remains an issue with the use of syngas as well. Regardless of whether carbon dioxide is recovered or whether air or oxygen are used for syngas production, hydrogen content of the gas typically is too high to allow use of conventional dry low NOx premixed combustion for NOx control. Therefore, diffusion flame combustion is used typically with steam or nitrogen added as a diluent to the syngas from oxygen blown gasifiers to minimize NOx emissions. Even so, exhaust gas cleaning may still be required. Thus, such systems, though cleaner and more efficient, typically cannot achieve present standards for NOx emissions without NOx clean-up methods.
A further problem is that the presence of diluent in the fuel increases mass flow through the turbine often requiring the bleeding off of compressor discharge air to reduce turbine rotor stresses. Since bleed off of compressor air must be limited to allow sufficient air for combustion and turbine cooling, the amount of diluent which can be added to the fuel is limited. Typically, NOx cannot be reduced below about ten parts per million (“ppm”) without operational problems, including limited flame stability. There are further efficiency loss issues. If nitrogen is added to dilute the fuel gas, there is an energy penalty related to the need to compress the nitrogen to the pressure required for mixing with the fuel gas. In addition, use of syngas in a gas turbine designed for natural gas increases turbine mass flow even without dilution for NOx reduction. Typically, to avoid excessive loads on the turbine rotor, operation is at a reduced turbine inlet temperature and/or with bleed of compressed air from the turbine compressor. Low BTU gases also have a high content of diluents and may require rotor protection.
It has previously been shown that rich pre-combustion with transfer of reaction heat allows low NOx formation in diffusion flame combustion; for example, as taught in U.S. Publication No. 2007/0037105 (U.S. patent application Ser. No. 11/439,727). Using a reactor such as that described in U.S. Pat. No. 6,394,791, the content of which is incorporated herein, the stoichiometric flame front temperature (“SFFT”) of high hydrogen content fuels can be reduced sufficiently to provide ultra-low NOx combustion. Unfortunately, some high hydrogen fuels are difficult to safely premix.